S T Q L L K E E N O N

2000 PNC PLAZA 500 WESI J E ~ F ~ K S O N S I REEI

MAIN (502) 333-6000 LOUISVILLt, KY 40202-2828

FAX (502) 333-6099

April 3,2012

VIA HAND DELIVERY

Jeff DeRouen Executive Director Kentucky Public Service Commission 21 1 Sower Boulevard Frankfort, KY 40601

w. DUNCAN CKOSBY 111 DIRECT DIAL: (502) 560-4263

duncan"crosby@skofim corn DIRECT FAX: (502) 627-8754

PUBLIC SERVICE CO \/I M IS S ION

RE: Joint Application o f Louisville Gas and Electric Company and Kentuckv Utilities Company for a Certificate o f Public Convenience and Necessitv for the Construction o f a Combined Cycle Combustion Turbine at the Cane Run Generating Station and the Purchase o f Existing Simple Cycle Combustion Turbine Facilities from Bluenrass Generation Company, LLC in LaGranne, Kentuckv Case No. 2011-00375

Dear Mr. DeRouen:

Enclosed please find and accept for filing the original and ten copies of Louisville Gas and Electric Company and Kentucky Utilities Company's Post-Hearing Brief in the above- referenced matter. Please confirm your receipt of this filing by placing the stamp of your Office with the date received on the enclosed additional copies and return them to me via our office courier.

Thank you.

Yours very truly,

W. Duncan Crosby 111

WDC:ec Enclosures cc: Parties of Record

400001 139844/802019 1

L O U I S V I L L E I L E X I N G T O N I F R A N K F O R T I H E N D E R S O N I M O R G A N F I E L D I 5 1 \ 0 1 l l l h l < 0 2 1

COMMONWEALTH OF KENTUCKY

BEFORE THE PUBLIC SERVICE COMMISSION

In the Matter of:

JOINT APPLICATION OF LOUISVILLE GAS AND ELECTRIC COMPANY AND KENTUCKY UTILITIES COMPANY FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY AND SITE COMPATIBILITY CERTIFICATE FOR THE CONSTRUCTION OF A COMBINED CYCLE COMBUSTION TURBINE AT THE CANE R'IJN GENERATING STATION AND THE PURCHASE OF EXISTING SIMPLE CYCLE COMBUSTION TURBINE FACILITIES FROM BLUEGRASS GENERATION COMPANY, LLC IN LAGRANGE, KENTUCKY

1 )

CASE NO. 201 1-00375

) )

)

JOINT APPLICANTS' POST-HEARING BRIEF

Respectfully submitted,

Kendrick R. Riggs Robert M. Watt, 111 Lindsey W. Ingrarn TI1 W. Duncan Crosby I11 Stoll Keenon Ogden PLLC 300 West Vine Street, Suite 2100 Lexington, Kentucky 40507 Telephone: (859) 23 1-3000

Allyson K. Sturgeon Senior Corporate Attorney LG&E and KU Services Company 220 West Main Street Louisville, Kentucky 40202 Telephone: (502) 627-2088 Email: allyson;stur,oeon@lge-ku.com

Counsel for Louisville Gas and Electric Company and Kentucky Utilities Company

Table of Contents

INTR.ODUCTION ........................................................................................................................... 1

PR.OCEDURAL HISTORY ............................................................................................................. 4

OVERVIEW OF PROPOSED PROJECT ....................................................................................... 5 ARGUMENT ................................................................................................................................... 7

THE COMPANIES’ REQUEST FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY SHOULD BE GRANTED ......................... 7

A . Cane Run 7 and the Bluegrass Facilities Are Needed to Allow the Companies to Replace the Capacity that Must be R.etired ........................... 9

1 . The Companies’ load forecast ....................................................... 10

2 . The SC-NRDC’s Assertion that the Companies’ Projected Capacity-Demand Gap Might Be R.educed by Additional Energy Efficiency Programs Is Unsupported and Does Not Affect the Need for the Proposed Gas-Fired Units on the

I .

Timetable the Companies Have Proposed ..................................... 12

B . The Construction of Cane Run 7 and the Purchase of the Bluegrass Facilities Will Not Create a Wasteful Duplication of Facilities ................ 15

C . Cane Run 7 and the Bluegrass Facilities Are the Least-Cost Solution ...... 16

1 . 2 .

3 .

4 .

The Companies’ Resource Assessment Process and Results ........ 17 There Are Good Operational Reasons to Build the Proposed NGCC at the Existing Cane Run Site ............................................ 18

The Bluegrass Facilities Are a Particularly Good Value for the Companies ................................................................................ 19

The SC-NRDC’s Criticisms of the Resource Assessment Are Not Reasonable .............................................................................. 20

THE COMPANIES’ APPLICATION FOR A SITE COMPATIBILITY CERTIFICATE SHOULD BE GRANTED ........................................................... 26

CONCLUSION .............................................................................................................................. 26

I1 .

1

INTRODUCTION

This case involves the Joint Application of L,ouisville Gas and Electric Company

(“LG&E”) and Kentucky Utilities Company (“KU”) (collectively, the “Companies”) for a

Certificate of Public Convenience and Necessity (“CPCN”) and a Site Compatibility Certificate

for the construction of a natural gas combined cycle (“NGCC”) generating facility at the

Companies’ Cane Run Generating Station, and for the purchase of Bluegrass Generation

Company, LLC’s facilities in LaGrange, Kentucky, which include three natural gas simple cycle

combustion turbines (“SCCT”).

In March 201 1, the Environmental Protection Agency (“EPA”) issued a proposed rule

aimed at reducing hazardous air pollutants from new and existing coal-and oil-fired electric

utility steam generating units (“HAPS Rule,” now called the Mercury and Air Toxics Rule, -

“MATs Rule”). The EPA issued the final MATs Rule on December 21, 2011, which was

published in the Federal R.egister on February 16, 2012.’ The EPA’s National Ambient Air

Quality Standards (“NAAQS”) will hrther restrict NO, and SO2 emissions beginning in 2016

and 2017.2 In addition, the EPA issued its final Cross-State Air Pollution rule (“CSAPR”) in

August 20 1 1, which provides limited allowances for NO, and SO2 emissions starting in 20 1 2.3

To comply with the foregoing regulations at all but one of their coal-fired steam

generating units (Trimble County Unit 2, which already has all of the requisite environmental

controls), the Companies must either install additional emission controls or retire and replace the

capacity. The Companies evaluated these decisions at each of their coal-fired steam generating

units in their comprehensive analysis that identified the recommended pro-jects and coimes of

77 Fed. Reg. 9,304 (Feb. 16, 2012) (to be codified at 40 C.F.R. pts. 60 and 63). Available at: h t t p : / / ~ ~ ~ . ~ ~ . g o ~ / f d ~ y ~ / p k g / F R - 2 0 12-02- 161pdfl20 12-806.pdf.

NOx NAAQS, 75 Fed. Reg. 6,474 (Feb. 9,2010); SO2 NAAQS, 75 Fed. Reg. 35,520 (Jun. 22,2010). ’ 76 Fed. Reg. 48,208 (Aug. 8, 2011) (to be codified at 40 C.F.R. pts. 51, 52, 72, 78, and 97). Available at: h t t p : / / ~ ~ ~ . ~ o . g o ~ / f d ~ y ~ / p k g / F R - 2 0 1 1-08-08/pdf/20 1 1-17600.pdf.

action (“201 1 Air Compliance Analysis”) which was submitted to the Commission in June 201 1

in their applications under KRS 278.1 83.4 Given the operating characteristics, age, and size of

the units, the Companies determined that the cost of additional emission controls on their coal-

fired units at the Cane Run, Green River, and Tyrone plants cannot be justified. Through the

201 1 Air Compliance Analysis, the Companies determined that these units should be retired

when required by the applicable environmental regulations. The decisions to retire these units

have not been disputed by any party. With the retirements of the Cane Run, Green River and

Tyrone coal-fired steam generating units, which have a combined capacity of 797 MW, and

projected increases in demand, the Companies will have a capacity shortfall in 2016 of 877 MW.

In April 201 1, the Companies filed their 201 1 Integrated Resource Plan (“201 1 IRP”)

with the Commission.’ The 201 1 IRP provides a detailed summary of the Companies‘ plan to

meet their hture energy requirements within their service territories at the lowest possible cost

consistent with reliable supply. Like the 201 1 Air Compliance Analysis, the 201 1 I W assumed

that the Green River, Tyrone and Cane Run coal-fired steam generating units would be retired at

the end of 2015. The Companies’ capacity needs through 2016, as identified in the 201 1 IRP,

are summarized in the table below.

-~ Case Nos. 201 1.-00161 and 201 1-00162. Case No. 20 1 1-00 140.

4

5

2

LG&E/I<TJ Resource Summary

Existing Resources Retirements Firm Purchases (OVEC) Total Supply

16% Reserve Requirements Difference from Target Reserve Margin

8,002 8,006 8,001 7,996 7,969 7,970 7,970

154 152 152 152 152 152 152 8,156 8,158 8,153 8,148 7,324 7,325 7,325

1,091 1,106 1,116 1,129 1,131 1,142 1,157 243 137 61 -40 -877 -952 -1066

19.6% 18.0% 16.9% 15.4% 3.6% 2.7% 1.3%

(797) (797) (797)

To meet the shortfalls projected above, the Companies submitted a request for proposals

(“RFP”) in December 2010 for electric energy and capacity. Responses to the RFP included

power purchase agreements and asset sale offers for gas, coal, nuclear, wind, biomass and solar

technologies. The Companies’ analysis of the RFP responses was completed in two phases. At

the conclusion of that process, the Companies determined that the least-cost alternative for

complying with the aforementioned EPA regulations arid meeting the 20 16 capacity and energy

need is to build an NGCC facility at the Companies’ Cane Run station (“Cane Run 7”) and to

purchase Bluegrass Generation Company, LLC’s existing SCCT facilities (“Bluegrass

Facilities”) in LaGrange, Kentucky. A detailed description of the foregoing process is set forth

in the 201 1 Resource Assessment attached as an exhibit to David Sinclair’s September 15, 201 1

Direct Testimony in this matter.

The sworn testimony and other evidence of record in this matter prove, without question,

that the public convenience and necessity require approval of the Companies’ proposal in this

case. Therefore, the Companies request issuance of the requested CPCN.

Peak reductions include the impacts of interruptible demands and demand-side management programs.

3

PROCEDURAL HISTORY

The companies filed their Joint Application, together with supporting testimony and

exhibits, on September IS, 20 1 1. The Kentucky Public Service Commission (“Commission”)

accepted the Joint Application, and issued a no-deficiency letter relating thereto, on September

30, 201 1.

The Commission granted full intervention in this proceeding to: the Kentucky Attorney

General, by and through his Office of Rate Intervention (“AG”); the Kentucky Industrial Utility

Customers, Inc. (“KITJC”); and the Sierra Club and Natural Resources Defense Council (“SC-

NRDC”). At the Companies’ request, the Commission held an informal conference in this

proceeding on October 11, 201 1, which was attended by Commission Staff, the Companies, and

all intervenors except for SC-NRDC because they had not yet intervened. The Commission

subsequently entered an order establishing a procedural schedule on October 18, 201 1.

Pursuant to the Commission’s procedural schedule, the Companies, Commission Staff

and SC-NRDC engaged in discovery. The AG and KIUC issued no discovery and they filed no

testimony. SC-NRDC is the only intervenor who filed direct testimony and they did so on

December 20,201 1. The Companies filed their rebuttal testimony on February 3,2012.

The Commission held a public hearing for the purpose of receiving public comment on

March 8, 2012. Notably, none of the members of the public who spoke at the hearing opposed

retiring the coal-fired units at Cane R.un, and a number spoke in favor of building Cane R.un 7.7

An evidentiary hearing occurred before the Cornmission on March 20, 2012. Following

the hearing, the Companies filed their response to the single hearing data request that was issued

at the March 20, 2012 hearing. This brief is filed pursuant to the schedule established at the

conclusion of the Commission’s evidentiary hearing.

’ Minutes of the Information Session and Public Hearing (Mar. 8, 2012).

4

OVERVIEW OF PROPOSED PROJECT

The Companies have proposed the construction of a new NGCC utilizing F-class gas

turbine technology at the Cane Run Station. They have also proposed the purchase of existing

Bluegrass Generation facilities in Oldham County, Kentucky which include three natural gas

simple cycle combustion turbines. The Bluegrass Facilities are already in operation.

The Companies? existing Cane Run site contains 510 acres in southwestern Jefferson

County and is suitable for Cane Run 7.8 The Site Assessment Report attached to Mr. Revlett’s

testimony shows that the site complies with the requirements of KRS 278.216.9 There is existing

infrastructure at the Cane Run site that may be used for Cane Run 7, and the new facility will

interconnect with existing transmission lines.” The use of the existing Cane Run site also

minimizes development risk associated with air permitting. Although Cane Run 7 will still be

required to obtain an air permit and to comply with all applicable environmental requirements,

the utilization of the existing emissions of Cane Run Units 4, 5 and 6 will allow the proposed

unit to effectively “net out” of the Prevention of Significant Deterioration air permitting process

that would be required for a new “green field” site.

When compared to existing facilities at Cane Run, emission of particulate matter and

NOx will be greatly reduced, while emissions of SO2 will be all but eliminated. As Jefferson

County is proposed to be classified as non-attainment for SO2, the county will gain significant

ground toward meeting the new National Ambient Air Quality Standard for SO2. The reduction

in SO2 and NOx emissions are also incorporated into meeting the Companies’ requirements

John N. Voyles Direct Testimony at 4. See Exhibit GHR-2 to Mr. Revlett’s Direct Testimony

8

9

lo Voyies Direct Testimony at 4. “ Id.

5

tinder the final Cross-State Air Pollution Rule allowance allocations.'2 Also, NGCC technology

does not produce combustion residuals that would require the same landfill needs as coal-fired

technology.

The Companies have concluded that the least cost option for environmental compliance is

With timely regulatory approval and receipt of the construction to construct Cane Run 7.

permits, completion of Cane Run 7 construction is expected to occur prior to the end of 201 5.13

As described above, taking into consideration the contemplated retirements and the

Companies' prqjected load forecast, the Companies will have a capacity shortfall of 877 MW in

2016. In addition to Cane Run 7, the Companies determined that the least cost option to meet the

shortfall is to purchase existing generation assets from Bluegrass Generation in Oldham Cotinty.

The Companies have submitted a copy of the executed Asset Purchase Agreement for those

assets. l 4

The Bluegrass Facilities entered service in June of 2002 and are located on a 60-acre site

in Oldham County. 'j The assets consist of three Siemens-Westinghouse 50 1 FD2 combustion

turbines (F Class) operating in simple cycle as peaking units. The combustion turbines provide

495 MW of summer capacity. Since commercial operation began, each unit has accumulated

approximately 1,000 operating hours and 340 starts.I6 At the proposed purchase price of $1 10

million, the resulting unit price for summer capacity is $222/kW. That price is significantly

cheaper than the comparable $850/kW estimate for constructing summer capacity at a green field

site in today's d01lars.l~ With timely regulatory approval from this Commission and the Federal

" Id. at 6 . Id. at 7.

l4 See Exhibit JNV-1 to Voyles Testimony. The executed version of the Asset Purchase Agreement was filed in this matter on September 20,20 1 1" l5 Voyles Direct Testimony, p. 1 1. l6 Id.

Id. at 12. 17

6

Energy Regulatory Commission, the Companies will be in a position to complete the purchase in

s u m e r 2012 in accordance with the terms of the Asset Purchase Agreement.

ARGUMENT

I. THE COMPANIES’ REQUEST FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY SHOULD BE GRANTED.

The statutory requirement for certificates of public convenience and necessity is

contained in KRS 278.020( I), which states:

No person, partnership, public or private corporation, or any combination thereof shall . . . begin the construction of any plant, equipment, property or facility for furnishing to the public any of the services enumerated in KRS 278.010 . . . until that person has obtained from the Public Service Conmission a certificate that public convenience and necessity require the service or construction. . . .

Kentucky’s highest court has construed ”public convenience and necessity” to mean: (1)

there is a need for the proposed facility or service; and (2) the new facility or service will not

create wasteful duplication. ’’ A finding of “need” is supported where there has been a showing of “a substantial

inadequacy of existing service” due to a deficiency of service facilities beyond what could be

19 C L T b supplied by normal improvements in the ordinary course of business. u stantial inadequacy

of existing service” is not required to be a currently existing deficiency, but rather may be a

deficiency expected a number of years into the future ”in view of the long range planning

necessary in the public utility field.”20 The prevention of “wasteful duplication” has been

interpreted to mean not only a physical multiplicity of facilities, but also an avoidance of

“excessive investment in relation to productivity or efficiency.”21 In considering the efficiency

Kentucky Utilities Co. v. Public Service Commission, 252 S.W.2d 885, 890 (Ky. 1952). l9 Id. ’O Kentucky Utilities Co. v. Public Service Commission, 390 S.W.2d 168, 171 (Ky. 1965). 21 Kentucky Utilities Co., 252 S.W.2d at 890.

7

of a proposed project, the Cornmission is not restricted to making a close comparison of the rates

that would result from various options.22 In other words, although cost is a factor, it is not the

only factor to be considered. As long as the project is reasonable and feasible, it meets that

standard set forth in 278.020( 1).13 The standard has been succinctly described as follows:

As we view it, if the . . . proposal is feasible (capable of supplying adequate service at reasonable rates) and will not result in wasteful duplication, the Public Service Commission is authorized to grant a certificate. . . . 24

As a public utility in the Commonwealth of Kentucky and regulated by the Commission,

the Companies are obligated under KRS 278.030(2) to serve their customers: "Every utility shall

furnish adequate, efficient and reasonable service . . . ." The Commission has further explicated

this requirement in the following regulations, with which the Companies must cornply:

(1) 807 KAR 5:041, Section 2 -- "Every utility shall furnish adequate service and facilities at rates filed with the commission, and in accordance with administrative regulations of the commission and applicable rules of the utility. Energy shall be generated, transmitted, converted and distributed by the utility, and utilized, whether by the utility or the customer, in such manner as to obviate undesirable effects upon the operation of standard services or equipment on the utility, its customers and other utilities. I'

(2) 807 KAR 5:041, Section S(1) -- "Each utility shall make all reasonable efforts to prevent interruptions of service, and when such interruptions occur shall endeavor to reestablish service with the shortest possible delay. Whenever service is necessarily interrupted or curtailed for the purpose of working on equipment, it shall be done at a time practicable, that will cause least inconvenience to customers, and those customers which may be seriously affected shall be notified in advance, except in cases of emergency. I'

77 I- South Central Rural Telephone v Public Service Commission, 453 S.W.2d 257,259 (Ky. 1970). l3 Kentucky Utilities Co., 390 S.W.2d at 172 - 173. 24 Kentucky Utilities Co., 390 S.W.2d at 175.

8

With those statutory and regulatory requirements in place, the Companies had to decide

how to best meet their customers’ needs in a least-cost fashion given the required retirements.

As explained in detail below, the Companies have identified that solution and have demonstrated

in this case a need for the construction of Cane Run 7 and purchase of the Bluegrass Facilities.

Further, a CPCN is needed now in order to take advantage of the favorable pricing of the

Bluegrass Facilities and so that the process of constructing Cane Run 7 can commence in time to

ensure compliance with the EPA regulations at issue.

A. Cane Run 7 and the Bluegrass Facilities Are Needed to Allow the Companies to Replace the Capacity that Must be Retired.

The Companies forecast that, with the retirement of the 797 MW of combined capacitjj of

the Cane Run, Green River, and Tyrone coal-fired steam generating units and projected load

increases they will have a capacity shortfall in 20 16 of 877 MW.” No party to this proceeding

has contested the Companies’ projected shortfall, and only the SC-NRDC has contested how to

meet it. Failing to fill that gap would severely compromise the Companies’ ability to provide

reliable service at a reasonable cost, ensuring that any unit failure or planned service outage

would send the Companies involuntarily into the market searching for capacity and energy, the

prices and availability of which would be largely beyond their control. The other alternative

would be to institute service curtailments-rolling blackouts-during times of high demand,

which would be an unacceptable outcome. Therefore, the need for the Companies’ proposed

gas-fired units is real and immediate due to the time required to purchase and build the required

facilities.

Joint Application 74 .

9

1. The Companies’ load forecast.

The Companies seek to ensure that their load forecast is prepared using sound methods

by people who are qualified professionals. There are three practices that the Companies employ

to help produce the most reasonable forecast possible:

1. Build and rigorously test statistically and economically sound mathematical

models of the load forecast variables;

TJse quality forecasts of future macroeconomic events, both nationally and in the

service territory, that influence the load forecast variable; and

Thoroughly review and analyze the model output to ensure that the results make

sense based on historical trends and the forecaster’s own sense and understanding

of long-tern trends in electricity usage.26

2.

3.

The Companies used this thorough and disciplined approach to create their 201 1 I F ? and

2012 joint load forecasts. The 2012 joint load forecast reflects a more recent view of the

economy, updated expectations for consumer behavior, and updated forecasts for major

customers. But the update from the 201 1 IRP forecast does not cause material differences in

total energy sales or peak hourly demand as seen in the table below, which compares combined

company energy sales and peak demand before the impact of demand-side management and

energy efficiency programs (“DSM-EE”) and interruptible load.27

26 Sinclair Testimony at 5. l7 Sinclair Testimony at 6 .

10

Year 2012 2013 2014 2015

-__I

Combined Company Energy Sales (GWh)

2011 IRP 2012 MTP 3 4 3 1 1 34,113

34,543 35,076 3 5,5 3 0 34,835

._.

Combined Company Peak Demand (MW)

Percent Percent Change 2011 IRP 2012 MTP Change

7,319 1.51% - 1.1 5% 7,2 10 - 1.52% 7,356 7,409 0.72% - 1.96% 7,477 7,504 0.37%

----.--I _-_- --__-.-

The methods and models employed to develop the forecasts are widely used in

36,097 36,615 37,074

the

35,256 -2.33% 7,603 7,583 -0.26% 35,741 - 2.3 9% 7,654 7,705 0.66% -- 36,126 -2.5 6% 7,760 7,789 0.37%

___.I_

industry and are similar to what the Commission has reviewed and accepted in the past. The

information and assumptions utilized by the models are reasonable because they are derived

from reliable and reputable sowces. The combination of sound methods and models with quality

data produced a forecast of energy and peak demand growth that is consistent with the historical

growth experienced by LG&E and KU. Therefore, the Companies’ load forecasts are

To determine the resources the Companies will need to meet projected demand, the

Companies subtract from projected load the demand savings that will be created by their DSM-

EE programs, as shown below:29

2011 2012 2013 2014 2015 2016 2017 DSM Peak Demand 220 272 320 378 418 459 500 Reduction (MW)

In the absence of additional capacity resources, the Companies’ load forecasts and

projected DSM-EE savings indicate significant capacity shortfalls beginning in 2016 due to the

need to retire the coal-fired generating units at the Cane Run, Green River, and Tyrone stations,

’* Sinclair Testimony at 7. 29 Sinclair Testimony at 7.

11

as well as projected load growth.30 These shortfalls begin at 877 MW in 2016 and increase to

over 1,000 MW by 2018.31

2. The SC-NRDC’s Assertion that the Companies’ Projected Capacity- Demand Gap Might Be Reduced by Additional Energy Efficiency Programs Is Unsupported and Does Not Affect the Need for the Proposed Gas-Fired Units on the Timetable the Companies Have Proposed.

The SC-NRDC offered the testimony of Dylan Sullivan C‘Mr. Sullivan”) to assert that

145 MW of the Companies’ projected 877 MW capacity-demand gap in 2016 could be filled

with additional demand side management/energy-efficiency (“DSM-EE”) programs.32 This

assertion is problematic for a host of reasons. First, as Mr. Siriclair explained during the hearing

in this case, Mr. Sullivan arrived at his claimed energy and demand savings calculations in a

manner contrary to what is usually done when developing DSM-EE programs. Mr. Sullivan

simply posited a quantity of annual energy savings to be achieved, and then spread those savings

over 75% of the hours in a year to compute a demand reduction.33 As Mr. Sinclair pointed out at

the evidentiary hearing, this top-down approach is the inverse of the correct, bottom-up

approach. The correct approach is to understand customers’ energy usage and the demand it

creates, craft programs to address that usage and demand, and then determine the likely peak-

demand reduction. That reduction may not be terribly great even for programs that produce

appreciable energy savings. For example, a residential high-efficiency lighting program may

produce attractive energy savings but relatively little peak-demand reduction because peaks tend

to occur during times of high sunshine and during working hours when people are not at home.

Sinclair Testimony at 13-14. 50

3 ’ Sinclair Testimony at 14. j2 Sullivan Testimony at 7. 33 Sullivan Testimony at 7. Even Mr. Sullivan acknowledged his approach was not “ideal”: “This is of course not the ideal way to analyze the peak load contribution of energy efficiency programs. [T]o do that I would analyze the load shape of energy savings from incremental measures.” Id. n. 16.

12

So Mr. Sullivan’s method of arriving at a claimed potential demand reduction is deeply flawed

and unrealistic.

Second, Mr. Sullivan made this claim without proposing a single DSM-EE program or

modification to the Companies’ existing suite of DSM-EE programs. Although he suggested a

few broad areas in which possible programs could be developed (some areas of which the

Companies already have programs), vague generalities of the kind Mr. Sullivan produced are

helpful neither in practice nor analysis.

Third, because Mr. Sullivan did not propose even one DSM-EE program, he did not

attempt to calculate the cost or cost-effectiveness of any such program or set of programs to

achieve his goal. Without such an analysis-including all four of the Commission-required

California Standard Practice Manual tests,34 not just the Total Resource Cost test’j-Mr.

Sullivan’s assertions about the value of unspecified DSM-EE programs are hollow. And the fact

that certain Ohio utilities are achieving, or are merely planning to achieve, energy savings more

to Mr. Sullivan’s liking does not affect the hollowness of his assertions concerning the

Companies because, as he acknowledges, electric utilities in Ohio are required by statute to

achieve certain aggressive levels of energy and demand savings, which is not true in Kentucky.36

Fourth, Mr. Sullivan gives short shrift to the Companies’ considerable achievements in

the DSM-EE field. Just last year, the Companies applied for, and the Commission approved in

In the Matter o j The Joint Application of the Members of the Louisville Gas and Electric Company Demand-Side Management Collaborative for the Review, ModiJication, and Continuation of the Collaborative, DShl Programs, and Cost Recovery Mechanism, Case No. 97-083, Order at 17-18 (Apr. 27, 1998). j5 See Sullivan Testimony at 6-7 (“A portfolio that as a whole exceeds a Total Resource Cost test (‘TRC’) of 1 will reduce the service territory’s energy bill: the current portfolio TRC of 3.01 shows the Company could likely expand the universe of measures covered by its programs, or market programs more heavily, saving more energy while still staying within the bounds of cost effectiveness”). 36 Sullivan Testimony at 5.

54

13

November, a significant expansion and extension of their DSM-EE programs.37 As included in

the Companies’ analysis in this case, the Companies’ project that their DSM-EE programs will

reduce what would otherwise be their peak load in 2016 by 459 MW.38 For their residential and

commercial customer classes, the Companies project that these programs will produce an

average of 1% annual energy-consumption reductions from 2012 through 2017,39 in line with

what Mr. Sullivan desires.40 Indeed, the EPA recently recognized certain of the Companies’

DSM-EE efforts by naming the Companies “ENERGY STAR Partners of the Year” for 201 1 .‘l

There are two other noteworthy points concerning Mr. Sullivan’s energy-efficiency

claims. First, the fact that the Companies’ extensive DSM-EE offerings do not include industrial

programs arose during the hearing in this case. As Mr. Bellar testified, the Companies are in

regular contact with their industrial customers, which are large consumers of electricity and

create significant demand. Those customers already have a large incentive to minimize their

demand and energy use, and they have indicated to the Companies that they have done so.42

They have fixther indicated that they do not want to be compelled to fund their competitors’

energy-efficiency efforts via programs run by the Companies,43 and given that they have a

statutory right not to be so om pel led,"^ it seems unlikely that an industrial program would be

successful. Moreover, the efforts the Companies’ industrial customers have already made to

reduce their demand and energy consumption are already reflected in the Companies’ load

forecasts.

37 Joint Application of Louisville Gas and Electric Company and Kentucky Utilities Company for Review, Modification, and Continuation of Existing, and Addition of New, Demand-Side Management and Energy-Eficiency Programs, Case No. 201 1-00134, Order (Nov. 9,201 1). 38 Sinclair Testimony at 7. j9 Sinclair Rebuttal Exh. DSS-1. 40 See Sullivan Testimony at 5-7. “ http://www.energys.t.ar.gov/index.cfr-n?fi~seaction=pt~awards.showAwardDetails&esa~id=4735 42 Video transcript at 16:02:47 - 16:05:39.

Video transcript at 16:02:47 - 16:05:39. J4 KRS 278.285(3).

43

14

Second and finally, Mr. Sullivan suggested during the hearing that his proposed energy

efficiency savings would produce $900 million of benefits arid would delay the need for Cane

Run 7 by five years.45 But Mr. Sullivan proposed no programs to achieve his hypothetical

savings, did not account for the cost (or cost-effectiveness) of programs to achieve such savings,

and gave no account for how such savings could be achieved so quickly, particularly given the

need for regulatory processes to occur and for programs to be developed and implemented.

More importantly, Mr. Sinclair showed conclusively in his rebuttal testimony that, even if Mr.

Sullivan’s hypothetical DSM-EE savings could be achieved on the timetable he asserts, the most

cost-effective means of meeting customers’ energy demands is for the Companies to purchase

the Bluegrass Facilities this year and to build the Companies’ proposed NGCC unit at Cane Run

for commercial operation by the beginning of 2016.46 Thus, Mr. Sullivan was simply incorrect

when he testified that implementing his hypothetical DSM-EE would delay the need for Cane

Run 7 ; Mr. Sinclair’s testimony showed that Cane Run 7 would still be needed in 2016 in a

world where Mr. Sullivan‘s desired DSM-EE could be achieved.47 In other words, no matter the

numerous problems with Mr. Sullivan’s assumptions concerning DSM-EE, even if he were

completely correct, it would not affect the Companies’ application or recommendations in this

case.

B. The Construction of Cane Run 7 and the Purchase of the Bluegrass Facilities Will Not Create a Wasteful Duplication of Facilities.

In addition to considering the need for Cane Run 7 and the Bluegrass Facilities, the

Commission must also evaluate whether they would result in a duplication of facilities through

an unnecessary multiplicity of facilities or an “excessive investment in relation to productivity or

Video transcript at 16:37:00 - 16:37:34. Sinclair Rebuttal Testimany at 6-9.

45

46

47 See Sinclair Rebuttal Exhibit DSS-9, Warkpaper~-CONFIDENTIAL\StrategistFiles\12a- 2~1-13C-6402~1\20 12MTP-SCDSM-12A-2X 1-1 3C-6402X1 .REP.

15

ef f i~ iency .”~~ In this case, none of the intervenors have claimed that a duplication of facilities

would occur if Cane Run 7 is built and the Bluegrass Facilities are purchased, and no such claim

could reasonably be made based on the evidence of record.4g

As set forth above, the Companies have established a need for the additional facilities

based on their comprehensive joint load forecast. Given the looming retirements and projected

load growth, the Companies must have 877 MW of additional capacity by 2016. And, as

explained below, the construction of Cane Run 7 and purchase of the Bluegrass Facilities will

allow the Companies to meet that capacity shortfall in a least-cost manner. Therefore, they will

be providing significant productivity and efficiency in relation to the investment required. For

all of those reasons, the construction and purchase on the schedule proposed by the Companies

will not result in a wastefiil duplication of facilities.

C. Cane Run 7 and the Bluegrass Facilities Are the Least-Cost Solution.

Although cost is not an express component of the determination of whether a proposed

project will meet the public convenience and necessity under KRS 278.020, it is well settled in

Kentucky that regulated utilities have the obligation to pursue a “least-cost strategy” for meeting

future capacity needs.’* The Companies take seriously their obligation to provide reliable, low-

cost service to their customers, and once the determination was made that additional capacity

would be needed to meet demand, the Companies conducted a Resource Assessment to evaluate

the options for meeting that need. That Resource Assessment evaluated self-build options

48 Kentucky Utilities Co. ,252 S.W.2d at 890. 49 Indeed, although the SC-NRDC witnesses make points relating to carbon pricing and demand side management programs, Mr. Chernick believes that the Bluegrass Facilities should be purchased. Chernick Testimony at 3 (“Unless the Staff or some other party identifies a problem in the pricing of the Bluegrass purchase, I believe the low price of that purchase and the possibility that the plant would not be available for purchase in the fiture argue for approval of the Bluegrass transaction.”). j0 See 807 KAR 51058, Section 8; Re: Small Power Producers, 60 PUR4th 574 (PSC Order of June 28, 1984).

16

(construction of the proposed NGCC), shared unit ownership, and market-based Power Purchase

Agreements (“PPA’y).5*

1. The Companies’ Resource Assessment Process and Results.

The Companies issued a request for proposals (“RFP”) on December 1, 20 10, for electric

energy and capacity to meet the capacity-demand gap identified in their 201 1 IRP and their 2012

load forecast. The RFP did not limit responses to a particular set of fiiels or generating

technologies. The specified capacity range for the responses was broad: the RFP encouraged

offers for firm summer and winter capacity ranging between 1 MW and 700 MW with the caveat

that the Companies may procure more or less than 700 MW and may aggregate capacity and

energy from multiple parties to meet its needs. The RFP cited the Companies’ preference for

longer-term proposals but did not exclude shorter-tenn proposals. In total, 18 parties responded

to the RFP with 50 offers, including power purchase agreements and asset sale offers from gas,

coal, nuclear, wind, biomass, and solar technologies.j2

The Companies analyzed the RFP responses in two phases. Phase I consisted of an initial

screening of the responses through the use of a scoring system (“Phase I Screening”) which

evaluated attributes including cost, term, and site viability. The goal of the Phase I Screening

process was to select the top candidates for each technology for hrther evaluation. Contrary to

SC-NRDC witness Paul Chernick’s (“Mr. Chernick”) claims,j3 the results of the Phase I analysis

show that the Companies clearly evaluated numerous wind, biomass, solar, and landfill gas

pr0posa1s.j~

51 Sinclair Testimony at 15- 17; 20 1 1 Resource Assessment 1 1.1 Appx. A. 52 Sinclair Testimony at 15. ’’ Chernick Testimony at 3 In. 22-25.

20 1 1 Resource Assessment 1 1.1 Appx. A. 54

17

Phase I1 of the analysis evaluated the top candidates (and various combinations of the top

candidates) from the Phase I Screening in more detail. The Phase I1 Analysis of RFP responses

was completed in two parts. In addition to the RFP responses, in the preliminary Phase I1

Analysis, the Companies evaluated the generic NGCC options considered in the development of

the 2011 IRP. For the final Phase I1 Analysis, the Companies, with the assistance of HDR

engineering firm, developed independent cost estimates for three different NGCC configurations.

Each estimate assumed the NGCC would be constructed at the Cane Run site. In the final Phase

I1 Analysis, the Companies evaluated these alternatives as well as other options from the

preliminary Phase I1 Analysis.

Based on the RFP and self-build analysis, the Companies determined that the least-cost

alternative for meeting the future capacity and energy needs of the Companies is to build a new

NGCC at the Cane Run Station (i.e., Cane Run 7) and purchase from Bluegrass Generation its

existing SCCT facility in Oldham County, Kentucky (Le., the Bluegrass Facilities). All of the

top five options in both the “No Economy Purchases” and the “Limited Economy Purchases”

involved building a new NGCC unit at Cane Run of some size greater than 600 MW and either

purchasing or entering into a PPA for the Bluegrass units.” In other words, the Companies’

proposal in this proceeding is well supported by their Resource Assessment.

2. There Are Good Operational Reasons to Build the Proposed NGCC at the Existing Cane Run Site.

Although KU will own a majority of the new Cane Run NGCC and there is existing

natural gas infrastructure at the E.W. Brown site, there are good operational reasons to place the

new NGCC at Cane Run rather than Brown. First, there is existing electrical transmission and

other infrastructure at Cane Run that the new NGCC will be able to use, extending the life of

” 201 1 Resource Assessment 1 1.8 Appx. H.

18

certain investments at that site. Second, using the existing Cane Run site rather than the Brown

site will allow Cane Run 7 to effectively “net out” of the Prevention of Significant Deterioration

air permitting process that would be required if the NGCC were placed at Brown. Third, to

minimize reliability and transmission system impacts, the existing Cane Run site is preferred

over other locations. Finally, having a geographical diversity of gas-fired generating units

increases the overall reliability of the Companies’ generating fleet by minimizing the impact of a

possible natural gas delivery disruption at a particular site.

3. The Bluegrass Facilities Are a Particularly Good Value for the Companies.

The Bluegrass Facilities are such a good value for the Companies and their customers

that even the SC-NRDC’s witness Chernick supports purchasing them,56 and Mr. Sullivan says

he would not “object” if the Commission found purchasing the units to be “~arranted.”’~ No

other party has objected to the Companies’ proposed purchase of the Bluegrass Facilities, and for

good reason: the purchase price is very attractive. The cost of the Bluegrass combustion turbines

(approximately $220/kW) is less than 30% of the cost of a new SCCT as set forth in the 2011

IRP. Moreover, the Bluegrass Facilities are available for sale now, and it is unclear whether

these units will be available for sale in the future. Furthermore, given the potential for other unit

retirements resulting from the proposed and existing EPA regulations, it is reasonable to assume

that the demand (and price) for these units could increase over time.

The Bluegrass Facilities are also particularly valuable to the Companies (as compared to

other possible purchasers of the units) because they will help the Companies manage reliability

risks associated with the Cane Run, Green River, and Tyrone stations as they approach

Chernick Testimony at 3. 56

j7 Responses and Objections from Environmental Intervenors to First Information Request of Commission Staff, Question No. 2(b) (Jan. 23,2012).

19

retirement. The units will also help the Companies manage risks while Cane Run 7 is being

constructed and placed into operation. The Bluegrass Facilities’ placement in the Companies’

system therefore makes them uniquely valuable for these reasons, whereas another purchaser

would have to pay transmission to move their power from the Companies’ system to market.

The Bluegrass Facilities will also help the Companies to manage risk associated with

environmental regulations. Under the Clean Air Act, regulated facilities are required to comply

with regulations such as the Mercury and Air Toxics rule no later than three years after the

effective date of the regulation, with a one-year extension available under certain circumstances.

The Companies have reasonably assumed that this period will be extended by one year at the

request of the Commonwealth of Kentucky. The Bluegrass Facilities will help the Companies

manage the risk of this extension not being granted. A final benefit of purchasing all three

Bluegrass units (versus only two) is that it will enable the Companies to defer the need for future

capacity by one year.

4. The SC-NRDC’s Criticisms of the Resource Assessment Are Not Reasonable.

Through its witness Mr. Chernick, the SC-NRDC appears to be primarily concerned with

how the Resource Assessment dealt with the following areas:

i) fuel price volatility,

(ii)

iii)

consideration of renewable generation, and

future carbon dioxide (“CO2”) regulations and prices.

A) Fuel price volatility

Concerning fuel price volatility, Mr. Chernick cites historical volatility in Northern

Appalachian coal costs as evidence fuel price volatility creates “financial and economic stress of

(sic) electricity consumers” and therefore that renewable generation such as wind should be

20

preferred. There are numerous problems with Mr. Chernick’s statement. First, the Companies

have historically purchased very little Northern Appalachian coal because they are much closer

to the coal fields of Kentucky and the Illinois Basin. Second, the Companies do not currently

have any long-term Northern Appalachian coal contracts. Third, Northern Appalachian coal

prices tend to be more volatile because it is a close substitute for metallurgical coal. Fourth, the

Resource Assessment focused on evaluating responses to the Companies’ RFP for capacity (of

which only one proposal had coal price risk) and self-build options (which were all natural gas-

fired) so the impact of coal price volatility on the existing generating fleet is not going to be a

material driver of revenue requirement differences between the various RFP and self-build

options.

Moreover, the Companies evaluated the Updated Final Phase I1 options under two

different long-term natural gas price forecasts: a higher one prepared by PIRA and a lower one

prepared by CERA.’* The graph in Rebuttal Exhibit DSS-5 shows these two forecasts as well as

one prepared by Synapse (co-authored by Mr. Chernick), a consulting firm that has testified for

SC-NRDC in a recent case before this Commission.” The long-term Synapse price forecast falls

in between the forecasts used by the Companies. Because “Mr. Chernick has not produced a

forecast of future natural gas prices for this proceeding,” the Companies cannot quantify the

specific impact of Mr. Chernick’s general assertions regarding natural gas prices.60 Although

Mr. Chernick may claim that the Companies did not evaluate various options under high or low

natural gas price cases, this graph clearly shows that the PIRA and CERA forecasts the

’* See 201 I Resource Assessment, Table 21, page 27. 59 Synapse’s AESC 201 1 gas price forecast was published in the Avoided Energy Supply Costs in New England: 201 1 Report, Synapse Energy Economic, Inc., July 2 1, 20 1 1, Amended August 1 1, 20 1 1, Exhibit D-9, Appendix D, p. D-1 0. Available at: httD:Nwww.svnapse-enerev.corn/r)ownloads/SvnapseReport.20 1 l-07.AESC.AESC-Studv- 201 1.1 1-0 14.pdf. 6o Resmnses and Obiections from Environmental Intervenors to First Information Request of Louisville Gas and Electric Company and Kentucky Utilities Company, Question No. 11 (Jan. 23,20 12).

I

21

Companies used provide a broad range of possible future prices and are above and below a

forecast that both Mr. Chernick and his clients have recently endorsed.

B) Natural gas prices and renewable generation

Wind generation is typically more expensive than NGCC technology, especially when

accounting for the costs associated with wind’s intermittent generating characteristics and low

availability at times of peak load. Still, higher natural gas prices would tend to economically

benefit wind generation. That is why it is important to note that while Mr. Chernick complains

that none of the wind options were evaluated under a different gas price forecast,61 they were, in

fact, evaluated under a gas price forecast that is higher than the one put forward by Synapse as

shown in Rebuttal Exhibit DSS-5 and yet were still not least-cost. Furthermore, as shale gas

continues to develop and put downward pressure on natural gas prices, this will make it more

difficult to develop wind and other renewable resources.62 As MIT researchers noted,

“[Clheaper gas serves to reduce the rate of market penetration of renewable generation. 7763,64

Mr. Chernick further objected that the Companies evaluated none of the RFP wind

proposals in the Final Phase I1 process, so the Companies created an option that replaced Cane

Run Unit 7 with nothing but wind proposals from the RFP. The Companies would be 257 MW

short in 2016 after Mr. Sullivan’s hypothetical DSM-EE and purchasing the Bluegrass Facilities.

Because wind conditions are usually very poor at the time of summer peak, only 15 percent of

6’ Chernick Testimony at 12, lines 1-4. Finlay, J., “Consultant: Without subsidies, renewables will get priced out by natural gas,” SNL Financial, October

1 1,201 1. A copy is attached the Sinclair Rebuttal Testimony as Appendix B. Jacaby, H., O’Sullivan, F, and Paltsev, S., “The Influence of Shale Gas on U.S. Energy and Environmental

Policy,” Economics of Energy and Environmental Policy, Vol. 1, No. 1, January 2012, p. 49. Available at: h~://globalchange.mit.edu/files/document/MITJFSPGC Reprint 12- 1 .pdf

“The Future of Natural Gas: An Interdisciplinary MIT Study,” MIT Energy Initiative, 201 1. Available at: hm://web.mit.edu/mitei/research/studies/documents/natural-gas-20 1 l/NaturalGas Report.pdf.

62

63

64

22

the nominal capacity rating was assumed to be available to meet this 257 MW shortfaL6’ To

meet this shortfall with wind, the Companies would have had to accept each unique proposal

(note that some bidders provided multiple proposals from the same wind project) offered in the

RFP but still would have only achieved 123 MW of firm summer capacity despite purchasing

820 MW of nominal capacity.66 Even after accepting every unique wind proposal from the RFP,

the Companies would still be 134 MW short of their target reserve margin in 2016.67 To meet

this remaining need and all fuhu-e resource needs, the Companies used Strategist software to

select the least-cost generating portfolio for the remaining years under this ”hypothetical DSM-

EE/wind” scenario (see Rebuttal Exhibit DSS-3 for a description of this portfolio). The revenue

requirements of this new wind-based portfolio were then evaluated using the same process

described above and used in the Updated Final Phase I1 analysis in the Resource Assessment.

This analysis showed that, even with the addition of Mr. Sullivan’s hypothetical DSM-EE

and purchasing the largest quantity of wind achievable from the RFP options, Cane Run 7 in

20 16 is the least-cost resource to meet the Companies’ customers’ needs. This provides further

evidence that constructing Cane Run 7 is the best solution. Not only was Cane Run 7 selected as

a least-cost resource, but the hypothetical wind portfolio had significantly higher PVRR than the

other three alternatives that included Mr. Sullivan’s hypothetical DSM-EE. Therefore, the

specific wind options that were proposed in the Companies’ RFP are not part of the least-cost

The use of 15 percent of nominal rating at time of peak is actually quite generous because NERC’s “201 1 Summer Reliability Assessment” indicated that ERCOT, MISO, and PJM assumed that wind generators have an availability of 8.7%%, 12.9%, and 13% respectively. Available at: httu://www.nerc.comlfiles/20 1 1%20Summer%20Reliabilitv%20Assessmentf, pages 36, 5 1, and 130. 66 This analysis included Response Nos. 6C, 6F, 7D, 8C, 10, 11, and 14 as shown in the 2011 Resource Assessment, 1 1” 1 Appendix A - Phase I Screening Results, p. 37. 67 To maintain consistency with previously filed testimony, figures for reserve margin shortfalls in 2016 are based on the 201 1 Load Forecast. The 2012 Load Forecast was used for the rebuttal analysis. The difference between these forecasts in 2016 is relatively minor as shown in Table 23 of the 201 1 Resource Assessment, page 29.

65

23

portfolio, and Mr. Chernick’s claim that wind energy is a competitive alternative at this time in

Kentucky is simply incorrect.@

C) Pricing carbon dioxide

Mr. Chernick argues that “it is certainly possible that the costs (for C02 emissions) will

be positive, and they may be very large,” although he fails to specify what “possible” means, the

timing of such regulations, and what “positive” means.69 Furthermore, Mr. Chemick admits that

he has not developed an actual “probability weighted average” of potential future CO2 emissions

costs and has not evaluated the level of C02 costs needed to refute the Companies’

recommendation in this ~roceeding.~’ However, because of his belief, Mr. Chernick feels that

the Companies should have included an unknown and unknowable fiiture C02 cost in its

evaluation of the RFP responses and its self-build options.

But it is not prudent to pay a premium today to address unknown and unknowable fixture

greenhouse gas regulations. If C02 regulations of the type contemplated by Mr. Chernick occur

at some fixture date, then the Companies can evaluate the least-cost options (including

renewables) at that time based on the state of technology at that time (which renewable

advocates claim will only get better and cheaper). Furthermore, many analysts believe that

In NGCC technology will at a minimum be a bridge to a lower carbon generation future.

that case, building Cane Run 7 to replace retiring coal generation can be seen as a first step in

moving the Companies’ generating fleet to one with lower carbon intensity. Finally, there is

71, 72

Chernick Testimony at 14, lines 7-8. 69 Chernick Testimony at 8 lines 18-19. ’* Responses and Objections from Environmental Intervenors to First Information Request of Louisville Gas and Electric Company and Kentucky Utilities Company, Question No. 10 (Jan. 23,2012). “Scott, M., “Shale Reserves: Gas Seen as Bridge between Old and New F Q ~ S of Power,” Financial Times, November 25, 20 1 1. Available at: h~://www.ft.com/cms/s/0/2c7 1975e-142f-1 le 1 -b07b-00 144feabdcO.html. ’’ “The Future of Natural Gas” at 2. See 11.2.5.

24

even some evidence that today’s wind technology is not a least-cost means to comply with COz

emission reduction targets.73

Moreover, recent developments from the EPA cast serious doubt upon any chance that

COz pricing schemes of the type the SC-NRDC envision will be realized, at least at the federal

level. On March 27, 2012, the EPA issued proposed New Source Performance Standards for

new, but not existing, fossil-fueled power plants.74 (Therefore, the Bluegrass Facilities will not

be subject to the proposed new rule.) The proposed standard would affect only those new

generating units that do not have permits and start construction within 12 months of the proposal,

and would apply a COz emission limit of 1,000 Ib/MWh to such units.75 Notably, Cane Run 7 is

projected to have a COz emission rate of well less than that amount, about 800 lb C O Z / M W ~ . ~ ~

Also, the rule appears to have been crafted explicitly to permit NGCC units like the proposed

Cane Run 7 to operate without being impacted, as the EPA’s Fact Sheet on the proposed rule

states: “New natural gas combined cycle (NGCC) power plant units should be able to meet the

proposed standard without add-on controls. In fact, based on available data, EPA believes that

nearly all (95%) of the NGCC units built recently (since 2005) would meet the ~tandard.”’~

Furthermore, EPA Administrator Lisa Jackson stated during a conference call concerning the

proposed rule on the day it was proposed, “We have no plans to address greenhouse-gas

emissions from existing plants.”78 Therefore, there is no reason to believe any reasonably

73 Lea, R., “Electricity Costs: The folly of wind power,” Civitas, January 2012, p.19. This study looks at the cost of various technologies to meet the United Kingdom’s COz reduction targets. Available at: hM,://www.civitas.ore.uMeconomv/electricitvcosts20 12.pdf. 74 http://epa.gov/carbonpollutionstandard/pdfs/2O . 120327proposal.pdf. ’’ http://epa.gov/carbonpollutionstandard/pclfs/2O 120327factsheet.pdf.

77 http://epa.gov/carbonpollutionstandarcUpdfs/2O 120327factsheet.pdf. ’* http://www. washin~onpost.com/hlogs/ezra-klein/postow-much-carbon-will-the-epas-new-power~plant-~les- actually-cutI20 12/03/27/gIQAuaTDeS-blog.htrnl

Video transcript at 10:52:33 - 10:53:00.

25

foreseeable COZ regulation will impact the cost-effectiveness of the proposed Cane Run 7

facility or the Bluegrass Facilities.

11. THE COMPANIES’ APPLICATION FOR A SITE COMPATIBILITY CERTIFICATE SHOULD BE GRANTED.

In addition to the CPCN discussed above, the Companies are also seeking a Site

Compatibility Certificate from the Commission pursuant to KRS 278.2 16. As discussed in detail

above, Cane Run 7 is proposed to be constructed at the existing Cane Run Station, which was

designed to accommodate additional generating units. The Companies have submitted a Site

Assessment Report as part of their Joint Application in this proceeding, and that report

demonstrates that the addition of Cane Run 7 while retiring the existing coal units will not cause

a negative impact to local property values, unduly increase traffic or noise, or materially change

the visual impacts of the facility from current conditions. None of the intervenors has in any way

questioned or challenged the findings of the Site Assessment Report. For all of those reasons,

the Companies’ request for a Site Compatibility Certificate for Cane Run 7 should be granted.

CONCLUSION

There is no dispute that the Companies will face a significant capacity shortage in the

near term-877 MW in 2016-as the coal units at the Cane Run, Green River, and Tyrone

generating stations are retired and demand increases over time. Likewise, there is no dispute that

the Companies must fill that capacity-demand gap to continue to serve their customers in a safe,

reliable, and cost-effective way.

The Companies have presented the Commission with a thorough, reasoned approach,

based upon a detailed Joint L,oad Forecast and a Resource Assessment, which support the

purchase of the Bluegrass Facilities and the construction of Cane Run 7 for an in-service date in

201 5. Neither the AG nor the KlUC has disputed that the Companies’ proposal is reasonable

26

and cost-effective. The SC-NRDC, on the other hand, appears not to object to the acquisition of

the Bluegrass Facilities, but they do object to building Cane Run 7 on claims that the Companies

have not adequately analyzed DSM-EE, renewable alternatives, and possible C02 pricing. But

as shown above and throughout the record of this proceeding, the SC-NRDC witnesses did no

serious analysis of their own, and made no alternative proposals for how to meet the capacity-

demand gap that nobody contests will soon impact the Companies and their customers. Indeed,

Mr. Sinclair showed in his rebuttal testimony that even if the Companies accepted the SC-

NRDC’s unfounded claims about DSM-EE load reductions and accepted all the wind proposals

actually offered to the Companies during their RFP, the Companies would still face a significant

capacity shortfall, and that the most cost-effective way of closing that gap would be precisely

what the Companies have proposed in this proceeding. Moreover, the EPA’s recent actions

concerning regulating COZ emissions from new generating units shows that building units like

Cane Run 7 is precisely what the EPA intends utilities to do, and that existing units like the

Bluegrass Facilities will not be affected by such regulations, nor does EPA intend to regulate

CO2 emissions from such units. The SC-NRDC’s witnesses have therefore failed to present any

plausible reason for the Commission to deny the Companies’ application, and the Companies

have presented ample reasons to grant it.

The Companies have established that purchasing the Bluegrass Facilities and building

Cane Run 7 are required by the public convenience and necessity, as set forth in KRS 278.020(1)

and case law, and the requested CPCN should be granted for that reason. In addition, for all of

the reasons set forth above, the Companies’ request for a Site Compatibility Certificate should

also be granted.

27

Accordingly, the Companies respectfully request that the Commission enter an order

providing the following relief:

1. Finding that a need exists to replace some 797 MW of retiring generating capacity

and to meet additional projected demand of about 80 MW by 201 6;

Finding that construction of a 640 MW net summer rating natural gas combined

cycle generating unit utilizing F-class gas turbine technology at the Companies’

Cane Rune Station and purchase of the Bluegrass Facilities in Oldharn County

consisting of three Siemens-Westinghouse SO 1 FD2 combustion simple cycle

turbines represent the most reasonable, least-cost resource for meeting the

Companies’ needs as set forth in the Companies’ Resource Assessment;

Finding that the construction of Cane Rune 7 and the purchase of the Bluegrass

Facilities as proposed in this proceeding will serve the public convenience and

necessity;

Granting KU and LG&E each a CPCN for their respective ownership interests in

Cane Run 7 and the Bluegrass Facilities as proposed (KU will own 78% and

LG&E 22% of Cane Run 7 and KTJ will own 31% and LG&E will own 69% of

the Bluegrass Facilities); and

Granting KTJ and LG&E each a Site Compatibility Certificate for their respective

ownership interests of Cane Run 7.

2.

3.

4.

5 .

28

Dated: April 3,2012 Respectfully submitted,

Kendrick R. Riggs Robert M. Watt, I11 Lindsey W. Ingram I11 W. Duncan Crosby I11 Stoll Keenon Ogden PLLC 300 West Vine Street, Suite 2 100 Lexington, Kentucky 40507-1 801 Telephone: (859) 23 1-3000

Allyson K. Sturgeon Senior Corporate Attorney LG&E and KU Services Company 220 West Main Street Louisville, Kentucky 40202 Telephone: (502) 627-2088

Counsel for Louisville Gus and Electric Company and Kentucky Utilities Compuny

400001.139844/403 1170.9

29

CERTIFICATE OF SERVICE

The undersigned hereby certifies that a true and correct copy of the foregoing Post-Hearing Brief was served on the following persons on the 3rd day of April, 2012, U.S. mail, postage prepaid:

Dennis G. Howard I1 Lawrence W. Cook Office of the Attorney General Office of Rate Intervention 1024 Capital Center Drive, Suite 200 Frankfort, KY 4060 1-8204

Michael L. Kurtz Kurt J. Boehm Boehm, Kurtz & Lowry 36 East Seventh Street, Suite 15 10 Cincinnati, OH 45202

Edward George Zuger 111 Zuger Law Office PLLC P.O. Box 728 Corbin, KY 40702

Kristin Henry Staff Attorney Sierra Club 85 Second Street San Francisco, CA 94 105

Shannon Fisk Joe F. Childers Senior .Attorney Attorney at Law Natural Resources Defense Council 2 N. Riverside Plaza, Suite 2250 Chicago, IL 60660

201 West Short Street Suite 3 10 Lexington, Kentucky 40507

Counsel for Louisville Gas and Electric Company and Kentucky Utilities Company